Attached files
| file | filename |
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| 8-K/A - Reef Oil & Gas Income & Development Fund III LP | v180012_8ka.htm |
| EX-23.2 - Reef Oil & Gas Income & Development Fund III LP | v180012_ex23-2.htm |
Estimate
of Reserves
And
Future
Revenues
Azalea
Properties
Prepared
For
Reef
Oil & Gas
Income
and Development Fund III, L.P.
As
of
December
31, 2009
Various
Properties
United
States
Prepared
By
Gleason
Engineering
4621
South Cooper
Suite
131 343
Arlington,
Texas 76017
(817)
472-8017
March 31,
2010
Michael J
Mauceli
Chief
Executive Officer
Reef Oil
& Gas Companies
1901 N
Central Expwy, Suite 300
Richardson,
Texas 75080
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Re:
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Reserve
and Economics Report
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|
|
Azalea
Properties Interests
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Mr
Mauceli:
At your
request, Gleason Engineering (Gleason) has prepared an estimate of hydrocarbon
liquid and gas reserves, and future production rates as of December 31, 2009
attributable to certain interests, which are owned by Reef Oil & Gas Income
and Development Fund III, L.P. These ownership interests are in wells located in
fourteen (14) states across the country with eighty-five percent (85%) of the
PV10 value being concentrated in the states of California, Louisiana, Oklahoma
and Texas. This report has been prepared using the updated guidelines of the
Securities and Exchange Commission (SEC). The economic analysis uses a 10
percent per year discount factor. The benchmark prices used are the preceding
12-month average of the first trading-day of the month spot prices posted for
oil and gas. Oil and gas prices and costs are held constant in the analysis.
Please be advised that while the parameters for product pricing and expenses
used were pursuant to the guidelines of the SEC, the conclusions of this
analysis should not be construed to be an estimate of the future value of the
reserve estimates.
The
summary table below presents the estimated net remaining hydrocarbon reserves as
of December 31, 2009 reviewed by Gleason Engineering. Hydrocarbon liquid volumes
are expressed in standard 42 gallon barrels and are comprised of crude oil,
condensate and natural gas liquids. All sales gas volumes are expressed in
thousands of cubic feet (MCF) at the official temperature and pressure bases of
the areas where the gas reserves are located.
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Estimated
Gross Remaining Reserves
Attributable
to Certain Wells
As
of December 31, 2009
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Reserve
Category
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Gross Oil
Volume
(bbl)
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Net Oil
Volume
(bbl)
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Gross Gas
Volume
(mcf)
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Net Gas
Volume
(mcf)
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Future Net
Cash Flow
( $ )
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PV @
10%
( $ )
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||||||||||||||||||
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Proved
Developed Producing
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186,002,255 | 458,291 | 179,134,883 | 1,548,381 | 18,638,444 | 9,831,860 | ||||||||||||||||||
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Proved
Undeveloped
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19,593 | 357 | 2,176,987 | 39,653 | 76,449 | 44,255 | ||||||||||||||||||
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Total
Proved
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186,021,848 | 458,648 | 181,311,870 | 1,588,034 | 18,714,893 | 9,876,115 | ||||||||||||||||||
Review Procedure and
Opinion
In our
opinion, the estimates of future reserves for the wells and locations reviewed
by Gleason Engineering were prepared in accordance with generally accepted
procedures for the estimation of future reserves.
In
performing our review, we relied upon data available from the commercial
databases of IHS Energy Group, and the records of certain public agencies, which
require the reporting of such data. Gleason also relied on proprietary
engineering and geologic data in the files of Reef as well as Lease Operating
Expense Summaries for each well reviewed. The proprietary engineering and
geologic data presented by Reef were accepted as represented with no revisions
or modifications. Reliance on the experience and expertise of Gleason
Engineering was made for those data not generally available through public
domain or commercial sources, or found in the proprietary files of
Reef.
Future Production Rates and
Reserve Estimates
Initial
production rates are based on a review of well test records and producing rates
obtained from commercial data sources, which compile public domain data.
Currently there are four hundred twenty (420) regulatory entities producing in
this property set. These entities contain an indicated 1,346 wells, more or
less, in which Reef owns an interest. Future production rates are based on the
trends identified with the historical production. This analytical approach is
referred to as decline curve analysis. Additional engineering and geologic data
were utilized to forecast undeveloped reserves. An analysis and interpretation
of production history, test records, and geologic mapping were conducted to
assist in the estimate of recoverable reserves from the captioned
leases.
Reserves
estimated as Proved Undeveloped were evaluated using available geology, offset
production histories and an evaluation of areal depletion to determine the
reasonable certainty of a well recovering reserves in sufficient volumes to
generate a financial return. A total of seventeen (17) opportunities were
identified and evaluated, however at the pricing structure dictated by the SEC
requirements, only one (1) opportunity was indicated to meet the requirements
satisfying the reserve definition for Proved Undeveloped.
Capital and Expense
Requirements
The
Reserves presented in the Table of Estimated Gross Remaining Reserves are
grouped into two categories. Those categories are, Proved Developed, and Proved
Undeveloped. Definitions for these categories are presented at the end of this
report.
Historical
expenses were analyzed for each property evaluated. Actual historical expenses,
prices and production taxes were used as a basis for the economic parameters of
the forecasts prepared
In the
case of undeveloped reserves reported, there is an expectation that certain
capital expenditures may be required to realize the production of the Oil and
Gas Volumes Estimated. Gleason Engineering has relied on the capital estimates
prepared by Reef’s engineering and operating personnel.
Oil and Gas
Pricing
Product
pricing for oil and gas volumes was based on the average NYMEX oil price and the
average Henry Hub gas price using the preceding 12-month average of the first
trading-day of the month spot prices, adjusted on a property by property basis
for gravity, quality and location. All properties are reported in the addendums
attached to this letter. Please note that those reserves identified as Proved
Undeveloped show indicated positive value for PV 10% for only one (1) property.
The remaining Proved Undeveloped properties were uneconomic at the pricing
schedule as required by SEC guidelines. It is believed that a change in pricing
in the future may have a positive impact on these assets. However, because of
the SEC guidelines, it is not possible to declare them as a valued asset for
this report.
General
In
general, the estimates of reserves for the wells and locations reviewed by
Gleason Engineering are based on data generally available through November 30,
2009. Reef provided ownership interest in the properties, and Gleason accepted
the extent and character of ownership as represented. No independent well tests,
property inspections, or audits of completion and operating expenses were
conducted as part of this study.
General
comments regarding this report and the estimation of future reserves and
revenues are presented in Addendum ‘A’. Addendum ‘B’ presents the SEC’s revised
oil and gas reserves definitions as presented in SEC Regulation S-X §210.4-10.
Addendum ‘C’ contains the consulting firm profile.
Neither
we nor any of our employees have any interest in the subject properties and
neither the employment to do this work nor the compensation is contingent on our
estimates of reserves for the properties, which were reviewed.
This
report was prepared for the exclusive use and sole benefit of Reef Exploration
and affiliate Companies. The data and work papers used in the preparation of
this report are available for examination by authorized parties in our offices.
Please contact us if we can be of further service.
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Sincerely,
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 |
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Gleason
Engineering
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Dennis
M Gleason, PE
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Serial
Number 49844
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ADDENDUM
‘A’
GENERAL
COMMENTS
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(1)
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The
reserve estimates presented in this report have been calculated using
deterministic procedures. The reserves shown in this report are those
estimated to be recoverable under the new guidelines of the Securities and
Exchange Commission (SEC). The definitions for oil and gas reserves in
accordance with SEC Regulation S-X are set forth in this report in
Addendum ‘B’.
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(2)
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The
estimated future net revenue shown in the cash flow projections is that
revenue which should be realized from the sale of the estimated net
reserves. Surface and well equipment salvage values have not been
considered in the revenue projections. Future net revenue as stated in
this report is before the deduction of federal income
tax.
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(3)
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The
discounted future net revenue is not represented to be the fair market
value of these reserves. The estimated reserves included in the cash flow
projections have not been adjusted for
risk.
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(4)
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The
reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and revenue, and all categories of reserves may be
subject to revision as more performance data become
available.
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(5)
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Extent
and character of ownership, oil and gas prices, production data, direct
operating costs, required capital expenditures, and other data furnished
have been accepted as represented. No independent well tests, property
inspections, or audits of operating expenses were conducted by our staff
in conjunction with this study.
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(6)
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If
investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such a person, with the
approval of our client, is invited to visit our offices at his own expense
so that he can evaluate the assumptions made and the completeness and
extent of the data available on which our estimates are
based.
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(7)
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Gleason
Engineering has used all methods and procedures it considers necessary to
evaluate the reserves and future revenues included in the
report.
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(8)
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Gas
contract differences, including take or pay claims, are not considered in
this report.
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(9)
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Gas
sales imbalances have not been taken into account in the reserve
estimates.
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(10)
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Unless
otherwise stated in the text, existing or potential liabilities stemming
from environmental conditions caused by current or past operating
practices have not been considered in this report. No costs are included
in the projections of future net revenue or in our economic analyses to
restore, repair, or improve the environmental conditions of the properties
studied to meet existing or future local, state, or federal
regulations.
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(11)
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Any
distribution of this report or any part thereof must include these general
comments and the cover letter in their
entirety.
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(12)
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This
report was prepared under the supervision of Dennis Michael Gleason,
Registered Professional Engineer, Serial Number 49844, State of
Texas.
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ADDENDUM
‘B’
DEFINITIONS
FOR OIL AND GAS RESERVES*
(1) Acquisition of properties.
Costs incurred to purchase, lease or otherwise acquire a property,
including costs of lease bonuses and options to purchase or lease properties,
the portion of costs applicable to minerals when land including mineral rights
is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs
incurred in acquiring properties.
(2) Analogous reservoir.
Analogous reservoirs, as used in resources assessments, have similar rock
and fluid properties, reservoir conditions (depth, temperature, and pressure)
and drive mechanisms, but are typically at a more advanced stage of development
than the reservoir of interest and thus may provide concepts to assist in the
interpretation of more limited data and estimation of recovery. When used to
support proved reserves, an “analogous reservoir” refers to a reservoir that
shares the following characteristics with the reservoir of
interest:
(i) Same
geological formation (but not necessarily in pressure communication with the
reservoir of interest);
(ii) Same
environment of deposition;
(iii)
Similar geological structure; and
(iv) Same
drive mechanism.
(3) Bitumen. Bitumen, sometimes
referred to as natural bitumen, is petroleum in a solid or semisolid state in
natural deposits with a viscosity greater than 10,000 centipoise measured at
original temperature in the deposit and atmospheric pressure, on a gas free
basis. In its natural state it usually contains sulfur, metals, and other
non-hydrocarbons.
(4) Condensate. Condensate is a
mixture of hydrocarbons that exists in the gaseous phase at original reservoir
temperature and pressure, but that, when produced, is in the liquid phase at
surface pressure and temperature.
(5) Deterministic estimate. The
method of estimating reserves or resources is called deterministic when a single
value for each parameter (from the geoscience, engineering, or economic data) in
the reserves calculation is used in the reserves estimation
procedure.
(6) Developed oil and gas reserves.
Developed oil and gas reserves are reserves of any category that can be
expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which
the cost of the required equipment is relatively minor compared to the cost of a
new well; and
(ii)
Through installed extraction equipment and infrastructure operational at the
time of the reserves estimate if the extraction is by means not involving a
well.
(7) Development costs. Costs
incurred to obtain access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas. More specifically,
development costs, including depreciation and applicable operating costs of
support equipment and facilities and other costs of development activities, are
costs incurred to:
(i) Gain access to and prepare well
locations for drilling, including surveying well locations for the purpose of
determining specific development drilling sites, clearing ground, draining, road
building, and relocating public roads, gas lines, and power lines, to the extent
necessary in developing the proved reserves.
(ii)
Drill and equip development wells, development-type stratigraphic test wells,
and service wells, including the costs of platforms and of well equipment such
as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)
Acquire, construct, and install production facilities such as lease flow lines,
separators, treaters, heaters, manifolds, measuring devices, and production
storage tanks, natural gas cycling and processing plants, and central utility
and waste disposal systems.
(iv)
Provide improved recovery systems.
(8) Development project. A
development project is the means by which petroleum resources are brought to the
status of economically producible. As examples, the development of a single
reservoir or field, an incremental development in a producing field, or the
integrated development of a group of several fields and associated facilities
with a common ownership may constitute a development project.
(9) Development well. A well
drilled within the proved area of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.
(10) Economically producible. The
term economically producible, as it relates to a resource, means a resource
which generates revenue that exceeds, or is reasonably expected to exceed, the
costs of the operation. The value of the products that generate revenue shall be
determined at the terminal point of oil and gas producing activities as defined
in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR).
Estimated ultimate recovery is the sum of reserves remaining as of a
given date and cumulative production as of that date.
(12) Exploration costs. Costs
incurred in identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of containing oil and gas
reserves, including costs of drilling exploratory wells and exploratory-type
stratigraphic test wells. Exploration costs may be incurred both before
acquiring the related property (sometimes referred to in part as prospecting
costs) and after acquiring the property. Principal types of exploration costs,
which include depreciation and applicable operating costs of support equipment
and facilities and other costs of exploration activities, are:
(i) Costs
of topographical, geographical and geophysical studies, rights of access to
properties to conduct those studies, and salaries and other expenses of
geologists, geophysical crews, and others conducting those studies.
Collectively, these are sometimes referred to as geological and geophysical or
G&G
costs.
(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals,
ad valorem taxes on properties, legal costs for title defense, and the
maintenance of land and lease records.
(iii) Dry
hole contributions and bottom hole contributions.
(iv)
Costs of drilling and equipping exploratory wells.
(v) Costs
of drilling exploratory-type stratigraphic test wells.
(13) Exploratory
well. An exploratory
well is a well drilled to find a new field or to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir.
Generally, an
exploratory well is any well that is not a development well, an extension well,
a service well, or a stratigraphic test well as those items are defined in this
section.
(14) Extension well. An extension
well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of
a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature and/or stratigraphic condition. There
may be two or more reservoirs in a field that are separated vertically by
intervening impervious, strata, or laterally by local geologic barriers, or by
both. Reservoirs that are associated by being in overlapping or adjacent fields
may be treated as a single or common operational field. The geological terms
structural feature and
stratigraphic condition
are intended to identify localized geological features as opposed to the
broader terms of basins, trends, provinces, plays, areas-ofinterest,
etc.
(16) Oil and gas producing
activities.
(i) Oil
and gas producing activities include:
(A) The search for
crude oil, including condensate and natural gas liquids, or natural gas (“oil
and gas”) in their natural states and original locations;
(B) The acquisition
of property rights or properties for the purpose of further exploration or for
the purpose of removing the oil or gas from such properties;
(C) The
construction, drilling, and production activities necessary to retrieve oil and
gas from their natural reservoirs, including the acquisition, construction,
installation, and maintenance of field gathering and storage systems, such
as:
(1) Lifting the oil and gas to the
surface; and
(2) Gathering,
treating, and field processing (as in the case of processing gas to extract
liquid hydrocarbons); and
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state,
from oil sands, shale, coalbeds, or other nonrenewable natural resources which
are intended to be upgraded into synthetic oil or gas, and activities undertaken
with a view to such extraction.
(17)
Possible reserves.
Possible reserves are those additional reserves that are less certain to
be recovered than probable reserves.
(i) When
deterministic methods are used, the total quantities ultimately recovered from a
project have a low probability of exceeding proved plus probable plus possible
reserves. When probabilistic methods are used, there should be at least a 10%
probability that the total quantities ultimately recovered will equal or exceed
the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned
to areas of a reservoir adjacent to probable reserves where data control and
interpretations of available data are progressively less certain. Frequently,
this will be in areas where geoscience and engineering data are unable to define
clearly the area and vertical limits of commercial production from the reservoir
by a defined
project.
(iii)
Possible reserves also include incremental quantities associated with a greater
percentage recovery of the hydrocarbons in place than the recovery quantities
assumed for probable reserves.
(iv) The
proved plus probable and proved plus probable plus possible reserves estimates
must be based on reasonable alternative technical and commercial interpretations
within the reservoir or subject project that are clearly documented, including
comparisons to results in successful similar projects.
(v)
Possible reserves may be assigned where geoscience and engineering data identify
directly adjacent portions of a reservoir within the same accumulation that may
be separated from proved areas by faults with displacement less than formation
thickness or other geological discontinuities and that have not been penetrated
by a wellbore, and the registrant believes that such adjacent portions are in
communication with the known (proved) reservoir. Possible reserves may be
assigned to areas that are structurally higher or lower than the proved area if
these areas are in communication with the proved reservoir.
(vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has
defined a highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves should be assigned in the structurally
higher portions of the reservoir above the HKO only if the higher contact can be
established with reasonable certainty through reliable technology. Portions of
the reservoir that do not meet this reasonable certainty criterion may be
assigned as probable and possible oil or gas based on reservoir fluid properties
and pressure gradient interpretations.
(18)
Probable reserves.
Probable reserves are those additional reserves that are less certain to
be recovered than proved reserves but which, together with proved reserves, are
as likely as not to be recovered.
(i) When
deterministic methods are used, it is as likely as not that actual remaining
quantities recovered will exceed the sum of estimated proved plus probable
reserves. When probabilistic methods are used, there should be at least a 50%
probability that the actual quantities recovered will equal or exceed the proved
plus probable reserves estimates.
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved
reserves where data control or interpretations of available data are less
certain, even if the interpreted reservoir continuity of structure or
productivity does not meet the reasonable certainty criterion. Probable reserves
may be assigned to areas that are structurally higher than the proved area if
these areas are in communication with the proved reservoir.
(iii)
Probable reserves estimates also include potential incremental quantities
associated with a greater percentage recovery of the hydrocarbons in place than
assumed for proved reserves.
(iv) See
also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this
section.
(19) Probabilistic estimate. The
method of estimation of reserves or resources is called probabilistic when the
full range of values that could reasonably occur for each unknown parameter
(from the geoscience and engineering data) is used to generate a full range of
possible outcomes and their associated probabilities of occurrence.
(20) Production
costs.
(i) Costs
incurred to operate and maintain wells and related equipment and facilities,
including depreciation and applicable operating costs of support equipment and
facilities and other costs of operating and maintaining those wells and related
equipment and facilities. They become part of the cost of oil and gas produced.
Examples of production costs (sometimes called lifting costs)
are:
(A) Costs of labor
to operate the wells and related equipment and facilities.
(B) Repairs and
maintenance.
(C) Materials,
supplies, and fuel consumed and supplies utilized in operating the wells and
related equipment and facilities.
(D) Property taxes
and insurance applicable to proved properties and wells and related equipment
and facilities.
(E)
Severance taxes.
(ii) Some
support equipment or facilities may serve two or more oil and gas producing
activities and may also serve transportation, refining, and marketing
activities. To the extent that the support equipment and facilities are used in
oil and gas producing activities, their depreciation and applicable operating
costs become exploration, development or production costs, as appropriate.
Depreciation, depletion, and amortization of capitalized acquisition,
exploration, and development costs are not production costs but also become part
of the cost of oil and gas produced along with production (lifting) costs
identified above.
(21) Proved area. The part of a
property to which proved reserves have been specifically
attributed.
(22) Proved oil and gas reserves.
Proved oil and gas reserves are those quantities of oil and gas, which,
by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible—from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and
government regulations—prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the
operator must be reasonably certain that it will commence the project within a
reasonable time.
(i) The
area of the reservoir considered as proved includes:
(A) The
area identified by drilling and limited by fluid contacts, if any,
and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable
certainty, be judged to be continuous with it and to contain economically
producible oil or gas on the basis of available geoscience and engineering
data.
(ii) In
the absence of data on fluid contacts, proved quantities in a reservoir are
limited by the lowest known hydrocarbons (LKH) as seen in a well penetration
unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii)
Where direct observation from well penetrations has defined a highest known oil
(HKO) elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology
establish the higher contact with reasonable certainty.
(iv)
Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are
included in the proved classification when:
(A) Successful
testing by a pilot project in an area of the reservoir with properties no more
favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the engineering
analysis on which the project or program was based; and
(B) The project has
been approved for development by all necessary parties and entities, including
governmental entities.
(v)
Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The price shall be the
average price during the 12-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such period, unless prices
are defined by contractual arrangements, excluding escalations based upon future
conditions.
(23) Proved properties. Properties
with proved reserves.
(24) Reasonable certainty. If
deterministic methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic methods are
used, there should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of confidence exists
if the quantity is much more likely to be achieved than not, and, as changes due
to increased availability of geoscience (geological, geophysical, and
geochemical), engineering, and economic data are made to estimated ultimate
recovery (EUR) with time, reasonably certain EUR is much more likely to increase
or remain constant than to decrease.
(25) Reliable technology. Reliable
technology is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to provide
reasonably certain results with consistency and repeatability in the formation
being evaluated or in an analogous formation.
(26) Reserves. Reserves are
estimated remaining quantities of oil and gas and related substances anticipated
to be economically producible, as of a given date, by application of development
projects to known accumulations. In addition, there must exist, or there must be
a reasonable expectation that there will exist, the legal right to produce or a
revenue interest in the production, installed means of delivering oil and gas or
related substances to market, and all permits and financing required to
implement the project.
Note to paragraph (a)(26):
Reserves should not be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are penetrated and evaluated
as economically producible. Reserves should not be assigned to areas that are
clearly separated from a known accumulation by a non-productive reservoir (i.e. , absence of reservoir,
structurally low reservoir, or negative test results). Such areas may contain
prospective resources (i.e. ,
potentially recoverable resources from undiscovered
accumulations).
(27) Reservoir. A porous and
permeable underground formation containing a natural accumulation of producible
oil and/or gas that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
(28) Resources. Resources are
quantities of oil and gas estimated to exist in naturally occurring
accumulations. A portion of the resources may be estimated to be recoverable,
and another portion may be considered to be unrecoverable. Resources include
both discovered and undiscovered accumulations.
(29) Service well. A well drilled
or completed for the purpose of supporting production in an existing field.
Specific purposes of service wells include gas injection, water injection, steam
injection, air injection, salt-water disposal, water supply for injection,
observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A
stratigraphic test well is a drilling effort, geologically directed, to obtain
information pertaining to a specific geologic condition. Such wells customarily
are drilled without the intent of being completed for hydrocarbon production.
The classification also includes tests identified as core tests and all types of
expendable holes related to hydrocarbon exploration. Stratigraphic tests are
classified as “exploratory type” if not drilled in a known area or “development
type” if drilled in a known area.
(31) Undeveloped oil and gas reserves.
Undeveloped oil and gas reserves are reserves of any category that are
expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for
recompletion.
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting
development spacing areas that are reasonably certain of production when
drilled, unless evidence using reliable technology exists that establishes
reasonable certainty of economic producibility at greater
distances.
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a
development plan has been adopted indicating that they are scheduled to be
drilled within five years, unless the specific circumstances, justify a longer
time.
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable
to any acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved
effective by actual projects in the same reservoir or an analogous reservoir, as
defined in paragraph (a)(2) of this section, or by other evidence using reliable
technology establishing reasonable certainty.
(32)
Unproved properties.
Properties with no proved reserves.
ADDENDUM
‘C’
GLEASON
ENGINEERING
4621
SOUTH COOPER, SUITE 131-343
ARLINGTON,
TEXAS 76017
(817)
472-8017 Fax (817) 472-0522
E-Mail:
dennis@gleason-engr.com
Web Site:
www.qleason-enqr.com
Gleason
Engineering is an engineering consulting company that specializes in the
evaluation and appraisal of oil and gas reserves. Using state-of-the-art
technology, we conduct field studies to produce reserve estimates and economic
predictions so that the value of your oil and gas assets can be maximized.
Gleason Engineering Company has professional experience evaluating reserve
potential and recovery in several oil and gas basins in the United States,
including: Anadarko, Arkoma, Delaware, Midland, Val Verde, East Texas, Gulf
Coast, South Texas, Fort Worth, Michigan, Williston, Green River, Powder River
and San Juan.
Gleason
Engineering has no direct or contingent participation in oil or gas ventures.
There are no conflicts of interest or concerns about maintaining the
confidentiality of our client’s data. The company is dedicated to providing the
highest level of integrity, technology, and service.
GLEASON’S
expertise includes:
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Exploration
and Prospect Evaluations
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Reserve Estimation and Evaluation Studies |
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Fair
Market Value Analyses
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Economic and Market Analyses |
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Forensic
Engineering and Expert Witness
Testimony
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Reservoir
Engineering
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Regional
and Detailed Geological Studies
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Reservoir
Characterization
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Geostatistical
Studies
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Minerals
Evaluations
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Petrophysical
Analyses
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QUALIFICATIONS
Dennis M.
Gleason is the president and owner of Gleason Engineering. He holds Master of
Science degrees from the University of Missouri-Rolla, in Geological Engineering
and Petroleum Engineering. He also holds a Bachelor of Science degree in Geology
from Wichita State University. His accumulated professional experience of more
than 30 years includes: supervision of drilling and completion operations, oil
and gas reservoir optimization studies, petrophysical evaluation and
interpretation, fair market evaluation, secondary recovery evaluation, property
acquisition and divestiture and business plan development.
Mr.
Gleason is a registered professional engineer in the State of Texas, Serial
Number 49844. He is also a member of the American Association of Petroleum
Geologists (AAPG), the Society of Independent Professional Earth Scientists
(SIPES), the Society of Petroleum Engineers (SPE) and Engineers Without Borders.
He is currently serving as a member of the National Board of Directors of
SIPES.